Frequently-Asked Questions (FAQ)

These Frequently Asked Questions (FAQs) are intended to clarify, explain, and promote better understanding of the pipeline integrity management rules. These FAQs are not substantive rules and do not create rights, assign duties, or impose new obligations not outlined in the existing integrity management regulations and standards. Requests for informal interpretations regarding the applicability of one or more of the pipeline integrity management rules to a specific situation may be submitted to PHMSA in accordance with 49 C.F.R. § 190.11.

FAQ-159.What constitutes an "incident" of the kind for which operators implementing performance-based programs must evaluate for implications to their pipelines and IM programs (192.913(b)(1)(v)?[03/09/2005]

FAQ-11.Who will be held accountable for implementing Integrity Management requirements in a case where an operator transfers pipeline assets to another company but retains responsibility, by contract, for maintenance and integrity management activities until some later date?[06/29/2004]

FAQ-161.Can prior assessments be relied upon to meet the requirement that operators begin assessment activities by June 17, 2004?[05/26/2004]

FAQ-1.What are the Pipeline and Hazardous Materials Safety Administration's objectives for the Integrity Management rule?[05/19/2004]

FAQ-2.Who must comply with the rule?[05/19/2004]

FAQ-3.Does the rule apply to operators of transmission pipelines for gases other than natural gas?[05/19/2004]

FAQ-9.Does the rule apply to gathering and other low-stress lines?[05/19/2004]

FAQ-10.If a pipeline subject to 192 Subpart O is sold, does the new operator "inherit" integrity management plans and deadlines from the original operator?[05/18/2004]

FAQ-155.In several places, the rule requires that operators follow Appendices in ASME/ANSI B31.8S. The title of both Appendices A and B in the standard indicate they are non-mandatory. Must the requirements in these Appendices be followed verbatim?[05/05/2004]

FAQ-12.If a pipeline transports both gas and liquids (e.g., some off shore lines), does the hazardous liquid integrity management rule or the gas integrity management rule apply?[02/20/2004]

FAQ-244.What is the OPS position with regard to implementation of "should" statements in industry standards that are invoked by the rule?[01/11/2006]

FAQ-167.How should the operator address "must" and "shall" statements in the standard? In some cases, the standard provides for an alternative action if the "must" and "shall" statements are not implemented.[06/29/2004]

FAQ-247.For plastic transmission pipeline, must I meet all of the requirements in the sections specified in section 192.901 or just those requirements specifically directed at plastic pipe?[08/31/2009]

FAQ-150.What requirements must an operator meet if there are no high consequence areas on any of its transmission pipelines.[06/20/2005]

FAQ-84.The Integrity Management Program portion of the rule [192.907] applies to all portions of a pipeline system that are in HCAs, including compressor stations, metering stations, and other equipment. What must an operator do to comply with the rule for these facilities?[03/04/2005]

FAQ-237.When must the baseline assessment be completed for piping installed after the effective date of the rule?[12/12/2006]

FAQ-124.The rule includes many requirements that do not have specified time periods for completion. Examples include gathering and integrating data and information on the entire pipeline, updating risk assessments when the results of assesments are available and identifying HCAs for new pipe. How soon must these actions be completed?[03/09/2005]

FAQ-196.Is there any time limit between step 2 and step 3 in the ECDA process (indirect exam and direct exam)?[01/14/2005]

FAQ-179.How long does an operator that has had no HCAs, and therefore no integrity management program, have to develop an integrity management program after it discovers a new HCA?[08/19/2004]

FAQ-238.What documentation must I include in my IM program to describe a "process" required by the rule?[04/18/2007]

FAQ-239.How much detail must I include when the rule requires that I "justify" an action or decision?[08/02/2006]

FAQ-202.DA vendors offer processes that include proprietary analysis techniques (similar to how ILI vendors use algorithms to classify anomalies). If my IMP written plan has to document my process for CIS/DCVG/etc. acceptance limits, how can I use vendors that wouldnt give away their intellectual property?[12/06/2004]

FAQ-140.What level of detail does OPS expect to see in initial IM frameworks for each of the required program elements?[06/09/2004]

FAQ-72.When must the Baseline Assessment Plan and Framework be completed?[05/20/2004]

FAQ-246.Section 192.901 lists the sections of Subpart O that apply to plastic transmission pipelines. Section 192.905, "How does an operator identify a high consequence area?" is not included. Do I need to define HCAs for my plastic transmission pipeline.[08/31/2009]

FAQ-174.The centerline of a pipeline may not be accurately determined via GIS or other method. The locations of structures (e.g., from aerial photography) may also involve inaccuracies. What provisions must be taken to address for inaccuracies in these measurements, in order to accurately determine the relative location of structures with respect to the pipeline?[10/02/2006]

FAQ-22.Why is it important that operators know the specific characteristics of high consequence areas their pipelines traverse?[08/14/2006]

FAQ-233.Does growth of an existing HCA, which introduces new length of pipeline segment into the HCA, constitute a "newly-identified HCA?"[03/14/2005]

FAQ-172.May an operator designate an entire segment as HCA (i.e., covered by the rule)?[01/14/2005]

FAQ-171.If Method 2 is being used to identify HCAs, can multiple adjacent HCAs be merged to create a single segment?[12/06/2004]

FAQ-200.Our company constructed a line many years ago with an MAOP of 1000 psi. Recently we extended the line and, expecting market growth, put in pipe with an MAOP of 1201 psi. But the only supply to the new segment is the old line. Can we look for HCAs in both segments using MAOP=1000 psi? If we do so, are we obligated to go through a derate/uprate procedure?[12/06/2004]

FAQ-208.Is the derivation of the PIR equation publicly available?[12/06/2004]

FAQ-211.What is the time period for the 20 persons in an area? 20 people for 10 min/day, 20 people for 2 hours/day, 20 people for 8 hours/day?[12/06/2004]

FAQ-145.Are parking lots considered to be outside areas occupied by people in the definition of an identified site (specifically, commercial or industrial parking lots and church parking lots)? If a PIR crosses the back portion of a parking lot where it is unlikely that people will congregate, should this area be considered an identified site? If so, is there any guidance on how many people per parking space should be used to compute the total of 20?[11/19/2004]

FAQ-144.What is the preferred method for calculating the Potential Impact Radius (PIR) of a leak of a non-flammable gas within the context of Pipeline Integrity Management?
The regulation refers to ASME B31.8S-2001 Section 3.2 for calculation of PIR for gases other than natural gas. However, this document only deals with flammable gases. ASME B31.8S-2001 allows alternate models to be used for calculating impact radius, but provides no guidance as to preferred methods of modeling non-flammable or corrosive gases.[10/25/2004]

FAQ-182.If a facility or site has 20 or more people visit throughout the day but never 20 or more at one time, does this meet the identified site criteria?[08/19/2004]

FAQ-183.If an operator initially selects method 1 to identify HCAs and later changes to method 2 for the same portion of its system, does this constitute a change in IMP that needs to be communicated to OPS/state?[08/19/2004]

FAQ-192.If an operator has a short line and wants to declare it as an HCA, and assess it respectively, does the operator have to count houses, buildings, and identified sites?[08/19/2004]

FAQ-176.Is a single home housing a disabled person considered an identified site?[08/18/2004]

FAQ-20.When must newly-identified HCAs be included in the program?[08/17/2004]

FAQ-162.If only a small portion of a building where more than 20 people gather is within the impact radius, why does the segment need to be considered a covered segment?[08/17/2004]

FAQ-163.Why does the length of an HCA segment vary depending on how close to the pipeline an identified site is located? If an identified site is close to the pipeline the HCA length is longer than if an identified site is further away. Shouldnt the HCA be the same?[08/17/2004]

FAQ-164.Why should the high consequence area extend from the beginning of the first circle to the end of the last circle containing an identified site? For identified sites close to the pipeline, this creates HCAs that appear unreasonably long.[08/17/2004]

FAQ-170.Must an operator continue to contact public safety officials in order to locate identified sites even if they dont respond?[08/17/2004]

FAQ-191.If a pipeline is determined to fall within an HCA due to its class location, does the operator also have to identify identified sites.[06/29/2004]

FAQ-195.How were the Fire Marshals notified of providing assistance in locating identified sites? Is there written communication (i.e., documentation) that operators can reference? A Federal Register notice describing this effort would be useful.[06/28/2004]

FAQ-117.How often must an operator update its building density survey and list of identified sites to determine if new HCAs have been created?[06/09/2004]

FAQ-146.Does a commercial or industrial building count as one building, or multiple buildings? For example a shipping and receiving warehouse. Would a two story office building with five offices count as five buildings or one?[06/09/2004]

FAQ-149.Must an operator treat all of its class 3 and 4 areas as high consequence areas?[06/09/2004]

FAQ-14.When must covered pipeline segments subject to the rule be identified?[05/19/2004]

FAQ-16.How will an operator determine if a pipeline is in an HCA?[05/19/2004]

FAQ-17.What is an identified site?[05/19/2004]

FAQ-151.Must off-shore platforms be treated as high consequence areas?[05/18/2004]

FAQ-15.Many operators have pre-defined segments on their pipeline (e.g., the length of pipe between two compressor stations or between consecutive isolation valves is considered a segment). When OPS refers to segments in HCAs in the rule, in what context is the term segment used?[05/17/2004]

FAQ-18.Are there practical limits on an operators search for identified sites?[05/17/2004]

FAQ-19.What are OPS expectations for operators to determine new or changed HCAs?[05/17/2004]

FAQ-21.Must non-pipe elements of a pipeline system in HCAs (e.g., compressor stations) be identified by 12/17/04?[05/17/2004]

FAQ-120.Who is an appropriate safety authority for locating identified sites?[05/17/2004]

FAQ-119.Can I use normal operating pressure in my potential impact circle calculations if that pressure is significantly below MAOP?[05/11/2004]

FAQ-121.Must facilities occupied by an operator's employees be considered in identifying HCAs?[05/11/2004]

FAQ-143.When determining "identified sites", does one have to consider standing traffic on roads/expressways under the "outside area or open structure" portion of the definition? If so, is there any guidance on how many people per vehicle should be used to compute the total of 20?[02/20/2004]

FAQ-205.Does an operator have to provide the original source documents for the covered segment of the pipeline? (Source document means actual pressure test chart for MAOP, mill test report on pipe, etc.) In the absence of original source material, will DOT accept inventory map data for pipeline information, MAOP database information, etc.?[12/06/2004]

FAQ-222.Must I consider information from portions of my pipeline not in HCAs when developing my integrity management program?[09/16/2004]

FAQ-81.What kinds of information must be integrated in performing a continual evaluation of pipeline integrity?[05/17/2004]

FAQ-28.What must an operator consider in prioritizing pipe segments for assessment and re-assessment?[08/17/2004]

FAQ-166.What qualification standards apply to Subject Matter Experts (SME) where that approach is used for risk assessment?[08/17/2004]

FAQ-169.Where the rule specifies certain segments with specific threats as "high risk segments," do these segments need to be in the top 50%?[08/17/2004]

FAQ-110.When the operator has identified a "new" HCA that results in the designation of additional covered segments, not previously identified as covered segments, subpart 192.905(c) requires the operator to incorporate these segments into the baseline assessment plan within one year. Subpart 192.921(f) requires the operator to complete the baseline assessment on these newly identified covered segments within ten (10) years from the date the new area is identified. Is the operator required to re-prioritize the baseline assessment plan segments per 192.921(b) each time a new segment is added even though the rule specifies a ten (10) year assessment schedule for these additional segments?[05/17/2004]

FAQ-220.Are assessments required for manufacturing and construction defects, including seam defects, if the pipeline has not been pressure tested in accordance with Subpart J?[01/04/2005]

FAQ-221.Relative to the requirement in 192.917(e)(3)(i), how much pressure increase (above the maximum experienced in the preceding five years of operation) will trigger the requirement to treat the segment as high risk for purposes of integrity assessments.[01/04/2005]

FAQ-219.Are integrity assessments required for manufacturing and construction defects, including seam defects, if the pipeline has been pressure tested in accordance with Subpart J?[09/16/2004]

FAQ-49.What type of pressure test can be used to assess pipeline integrity?[10/20/2004]

FAQ-177.Can operators aggregate ECDA regions after the process is started and they determine that some regions have common features?[08/19/2004]

FAQ-175.What is the definition of complementary technologies for selection of ECDA indirect inspection tools?[08/18/2004]

FAQ-48.What kind of tool can an operator use to conduct integrity assessments by internal inspection?[08/17/2004]

FAQ-33.The rule requires that 50% of the covered segments be assessed by December 17, 2007. For purposes of determining the 50% criterion, does an operator use the total mileage that has been and will be assessed, or just the mileage that has been determined to be in an HCA? (For example, most operators who use internal inspection will pig a greater distance than just the portion of the pipeline that can affect an HCA.)[05/20/2004]

FAQ-57.How soon must the results of pipeline integrity assessment be evaluated?[05/20/2004]

FAQ-26.When must baseline assessments be completed?[05/19/2004]

FAQ-34.For purposes of establishing the deadlines for completing baseline assessments, what is the date on which an assessment is considered complete?[05/18/2004]

FAQ-152.Must an assessment completed prior to the effective date of the rule have considered all applicable threats in order to be treated as a baseline assessment?[05/18/2004]

FAQ-53.For operators having line pipe in states that have a pressure testing requirement, will satisfying the state requirement also suffice for satisfying the integrity assessment requirement of the integrity management rule?[05/17/2004]

FAQ-29.Can operators count prior assessments of low-risk segments used as baselines against the requirement to complete 50% of their covered mileage by December 17, 2007?[04/27/2004]

FAQ-35.Must all of the highest risk segments be assessed by December 17, 2007, or will OPS allow operators some flexibility to deal with practical issues in scheduling assessments?[04/08/2004]

FAQ-55.A reduction in operating pressure can provide an equivalent level of safety as that provided by a Subpart J pressure test. Is a pressure reduction an acceptable integrity assessment method?[04/08/2004]

FAQ-25.Under what conditions should the Baseline Assessment Plan be modified?[02/20/2004]

FAQ-38.If an operator has multiple operating companies, does OPS require the operator to produce a single Baseline Assessment Plan for the entire company, or can an operator create multiple plans to align with its internal management practices?[09/07/2004]

FAQ-36.If an operator develops a single Baseline Assessment Plan that covers both intra- and interstate pipelines, does the need to complete assessments on 50% of the pipeline mileage in HCAs apply to both intra- and interstate line segments, or just interstate line segment mileage? Should the companys Plan identify whether line segments are intra- or interstate?[06/29/2004]

FAQ-133.Must I do a full assessment every 7 years if my pipeline is subject to threats other than external and internal corrosion.[09/27/2006]

FAQ-235.If Guided Wave UT is used as part of the ICDA process, is it considered "other technology" requiring notification to OPS/states?[08/30/2006]

FAQ-242.How can I demonstrate that I have applied more restrictive criteria the first time I used ECDA (required by 192.925(b)(1)-(3) and NACE-0502-2002)?[08/02/2006]

FAQ-243.What does PHMSA expect to see in a direct assessment feasibility study?[08/02/2006]

FAQ-232.What timeframes apply to "discovery" of conditions presenting a potential threat to the integrity of a pipeline when using Direct Assessment?[06/09/2005]

FAQ-218.If DA is not currently accepted as a primary assessment method for third party damage, and the threat of third party damage is present, does the rule require that DA always be accompanied by either a pressure test, or ILI, or another assessment method that is capable of assessing third party damage?[03/14/2005]

FAQ-223.What kind of data must I collect and evaluate to use stress corrosion cracking direct assessment (SCCDA)?[03/09/2005]

FAQ-158.Must historical operating conditions be considered, or only current operating conditions, when using ICDA?[12/06/2004]

FAQ-197.If you learn something in the post assessment step that may change the results in another ECDA, is there a time limit when you have to reassess that covered segment?[12/06/2004]

FAQ-198.If Guided Wave UT is used as part of the ECDA process, is it considered "other technology" requiring notification to OPS/states?[12/06/2004]

FAQ-203.For the first time using DA you were required to do an extra direct examination. Does this mean the "first time" on each covered segment, or the first time you do DA (ever)?[12/06/2004]

FAQ-213.At what point during ECDA does one move from severe, moderate, minor to immediate, scheduled, monitored?[12/06/2004]

FAQ-217.In Section 192.919(b), the rule states there must be an explanation of why assessment methods are chosen to assess the integrity of the line pipe. Does this mean the methods must be chosen and explained for all segments before the assessment begins, possibly by using some sort of decision tree, or does this mean that assessment methods can be explained after the assessment is complete? For example, an operator may plan on using an ILI tool for a segment but due to last minute budget restrictions must now hydrotest the segment. Will this last minute change cause a negative effect in an OPS audit even though the operator explains the reasons for the change and the reasons for the assessment method after the assessment is complete?[12/06/2004]

FAQ-126.Can Internal Corrosion Direct Assessment (ICDA) be used on a dry-gas system that was used previously to transport wet gas?[09/03/2004]

FAQ-187.Discussion at the Houston workshop implied an operator needs to justify use of DA. Since DA is an accepted assessment method in the rule, why does an operator need to justify it over ILI or hydrotesting?[08/19/2004]

FAQ-193.Currently, no standard exists for ICDA. How can we include ICDA in our plan when there is no accepted standard?[08/19/2004]

FAQ-105.If an operator has no records indicating that a pipeline section contained water or other electrolytes, is the lack of records sufficient to demonstrate that ICDA is unnecessary downstream of that location until the next feed injection point?[06/09/2004]

FAQ-128.When using Stress Corrosion Cracking Direct Assessment (SCCDA), must I consider conditions on portions of my pipeline not in high consequence areas?[06/09/2004]

FAQ-129.Can I use an indirect assessment tool for ECDA that is not listed in Table 2 of NACE RP-0502-2002?[06/09/2004]

FAQ-141.A spike test can be very useful for assessing some threats, including seam issues. Can a spike test be used as an assessment method?[06/09/2004]

FAQ-104.ASME/ANSI B31.8S, Appendix B, section B1.3, Indirect Examinations, states that the secondary indirect examination method must evaluate at least 25% of each ECDA region. NACE Standard RP0502-2002, section 4.1.2 states that the indirect inspection step requires the use of at least two inspections over the entire length of each ECDA region. The requirements in the two standards appear to conflict. Which requirement should be implemented?[05/11/2004]

FAQ-107.Section 192.927(c)(5)(iii) states that the ICDA plan must include "provisions that analysis be carried out on the entire pipeline in which covered segments are present..." Please clarify what sections of the pipeline must the operator conduct this analysis. Also, please define the term "analysis." Is this intended to be ICDA pre-assessment or some other analysis?[05/11/2004]

FAQ-127.Must I notify OPS (or the appropriate State) if I plan to use ICDA to assess a system transporting gas with an electrolyte nominally present in the gas stream?[04/08/2004]

FAQ-130.Section 192.925(b)(3)(iii) requires notification procedures for any changes to my ECDA plan. Does this mean I have to notify OPS every time my plan changes?[04/08/2004]

FAQ-147.Does an operator have to do a direct assessment for internal corrosion (where pigging and hydrostatic testing are impractical) if the operator can demonstrate by historical records such as gas quality, internal inspections, etc. that they have never identified an internal corrosion problem and that conditions conducive to internal corrosion do not exist?[04/08/2004]

FAQ-109.Section 192.921(a)(2) requires that pressure tests performed to satisfy rule assessment requirements must be conducted in accordance with subpart J. ASME/ASNI B31.8S, section 6.3 states that the details for conducting pressure tests are in ASME B31.8. These two documents contain different requirements for conducting pressure tests. Which document should take precedence?[04/06/2004]

FAQ-41.Does the requirement that gas pipeline operator establish assessment intervals not to exceed a specified number of years mean calendar years (i.e., pipe assessed in 2004 must be re-assessed during 2011) or actual years? [06/09/2004][02/22/2016]

FAQ-275.For reassessments using ILI, are verification digs required if the ILI tool does not show any defects/anomalies? The baseline assessment and/or previous reassessment was completed and anomalies were repaired, as needed.[07/28/2011]

FAQ-40.How often must periodic integrity assessments be performed on HCA pipeline segments after the baseline assessment is completed?[05/03/2006]

FAQ-42.Must operators conduct re-assessments before they have completed all baseline assessments?[05/03/2006]

FAQ-43.Can a re-assessment interval be extended beyond the maximum interval specified in 192.939?[05/03/2006]

FAQ-207.Table 3 of ASME/ANSI B31.8S indicates that reassessment intervals must be 5 years for some instances in which test pressure was higher than would be required by Subpart J. If I conduct my assessments in accordance with Subpart J, must I reassess more frequently than once every seven years?[05/03/2006]

FAQ-236.If I have hydrostatically tested my pipeline to a test pressure different than those listed in table 3 of ASME/ANSI B31.8S, how can I determine an extended reassessment interval?[01/04/2006]

FAQ-132.How do I determine a new reassessment schedule if I identify defects requiring remediation using ICDA during a CDA assessment?[12/06/2004]

FAQ-216.Assuming a system operating below 30% SMYS and reassessment every 20 years, how much of a system must be assessed via CDA at the 7 and 14 year intervals? How do we determine where we must use CDA?[12/06/2004]

FAQ-228.Can the conduct of a successful CDA assessment extend the interval until the next required assessment using ILI, pressure testing, DA, or other technology?[10/08/2004]

FAQ-178.If a line was operating at <30% SMYS and reassessment schedules had been established based on this stress level, what requirements would need to be adopted before the line stress is raised to >30% SMYS?[08/19/2004]

FAQ-185.Might OPS consider revising the rule, if experience indicates that longer reassessment intervals could be acceptable?[06/29/2004]

FAQ-68.Must tool accuracy be considered when determining if an anomaly detected by in-line inspection meets repair criteria?[08/14/2006]

FAQ-215.ASME B31.8S states that Immediate conditions shall be examined within five days after determination of the condition. Is this 5 day requirement part of the Final Rule?[08/14/2006]

FAQ-241.May I exclude metal loss indications of >80% wall loss from immediate repair requirements per 933(d)(1), if B31G or RSTRENG predict a failure pressure of greater than 1.1 times MAOP?[08/02/2006]

FAQ-224.What actions must I take on non-covered segments if I find corrosion during an assessment of segments in HCA?[03/09/2005]

FAQ-229.Must I include a safety factor when calculating an acceptable reduced operating pressure [per 192.933(d)(1)] for the interim period until immediate conditions can be repaired?[03/09/2005]

FAQ-225.Must I fix anomalies found in non-covered segments?[01/04/2005]

FAQ-56.Do the anomaly repair schedule requirements in 192.933(d) apply to all previous internal inspection runs performed by the operator, or just the integrity assessments required by Subpart O (i.e., the baseline assessment and subsequent integrity assessments)?[06/09/2004]

FAQ-65.If an operator elects to use an assessment conducted prior to 2002 as its baseline assessment [per 192.921 (e)], how long does the operator have to review the results of the prior assessment and identify any anomalies that have not already been repaired or remediated that meet the criteria established in 192.933?[06/09/2004]

FAQ-66.If a covered segment is relatively short (e.g., only 2 miles in length), yet the operator internally inspects a longer portion around this segment (e.g., 50 miles from pig launcher to receiver), do the repair schedules in 192.933 apply to the covered segment or the entire distance over which the pig is run?[05/17/2004]

FAQ-67.The rule requires that an operator temporarily reduce pressure if an immediate repair condition is discovered (192.933(d)(1)). Can the temporary reduction in operating pressure be based upon previous maximum allowable operating pressures?[05/17/2004]

FAQ-70.Must anomalies identified during pig runs not considered "baseline" or "re-assessments" under the rule be repaired in accordance with the rule's repair criteria?[05/17/2004]

FAQ-134.How soon must I reduce pressure after identifying an immediate repair condition?[04/12/2004]

FAQ-58.What constitutes "discovery of a condition"?[04/08/2004]

FAQ-135.Must I consider segments not in HCAs when evaluating my pipeline after discovering corrosion in a covered segment?[04/08/2004]

FAQ-90.When must operators implement additional preventive and mitigative measures? For example, how long after completing the baseline assessment for a segment can an operator take to conduct a risk analysis and determine whether additional preventive or mitigative actions are needed (including the need for ASVs/RCVs)? If an operator determines that additional actions are warranted, how long does it have to implement them?[03/13/2007]

FAQ-230.What is the maximum interval for "semi-annual" and "quarterly" leak surveys (192.935(d)(3))?[11/19/2004]

FAQ-180.How will OPS evaluate required "enhancements" for operators that are already operating at high level with respect to damage prevention measures?[08/19/2004]

FAQ-113.Section 192.935(b)(2) uses the term "determines ... is a threat to the integrity of a covered segment." What is intended by the word "threat" in this context, such that the subsequent actions (e.g., relocating the line) are required to be implemented?[04/20/2004]

FAQ-86.What criteria must an operator use in determining whether automatic shut-off valves or remote control valves are required to protect HCAs?[04/06/2004]

FAQ-137.Over what time period should performance measures be determined? How often should they be updated?[07/15/2005]

FAQ-209.As originally published, the rule required that all performance measures be submitted to OPS on a semi-annual basis. Current discussion indicates only the four overall measures of B31.8S, Section 9.4, must be submitted. Which is correct?[12/06/2004]

FAQ-186.Assume that an operator runs an inline inspection tool through a 50-mile segment of pipeline, not all of which is HCA, and a new HCA is subsequently identified within the inspected pipeline. When submitting semi-annual performance measures, can the operator take credit for the previous inspection when reporting "number of miles inspected versus program requirements"?[08/19/2004]

FAQ-194.Will DOT develop an official reporting form for semi-annual reporting of the four overall measures?[06/23/2004]

FAQ-136.One of the four overall performance measures required by 192.945(a) is the number of leaks, failures, and incidents (classified by cause). What is the threshold an operator should use for reporting leaks, failures, and incidents?[05/18/2004]

FAQ-30.Will operators need to seek waivers from OPS in order to change assessment schedules after the initial Baseline Assessment Plan has been developed?[05/20/2004]

FAQ-31.Section 192.909(b) requires that operators notify OPS of program changes that may modify the schedule for carrying out the program elements. Must operators notify OPS every time they change their assessment schedules?[04/08/2004]

FAQ-97.What types of notifications are required by the rule?[06/01/2009]

FAQ-245.If PHMSA completes a review of my notification for use of "other technology" and has no objections, must I still wait the remainder of the 180 days before I can implement the technology?[04/27/2006]

FAQ-99.What information must be in a notification?[09/03/2004]

FAQ-153.Must I notify OPS/state regulators if I plan to use a different model for ICDA than the one referenced in the rule?[09/03/2004]

FAQ-181.Is a safety related condition notification required when an operator implements a pressure reduction for an immediate repair? What about other pressure reducing requirements in the IM rule, is a notification required per 191.23?[06/29/2004]

FAQ-111.What level of change satisfies the terms "significantly modify" or "substantially affect" as used under subpart 192.909(b) regarding notification requirements for changes to an operators integrity management plan?[06/09/2004]

FAQ-206.New York CRR 255 mandates any pipeline operating above 125 PSIG is classified as a "transmission line". Will operators be required to develop an IMP for NY transmission lines even though under 192 these lines would not be defined as transmission pipelines?[12/06/2004]

FAQ-210.If the gas transmission pipeline is under state jurisdiction, should performance measures, waivers, etc., be sent to the states commission rather than OPS?[12/06/2004]

FAQ-276.With regard to FAQ 274 - Is the operator required to directly examine the entire surface of the carrier pipe within the casing?[09/08/2011]

FAQ-277.NACE RP 0502-2002 section 5.1.2 states "The Direct Examination Step requires excavations to expose the pipe surface so that measurements can be made on the pipeline and in the immediate surrounding environment." What tools can an operator use to satisfy this requirement for a pipeline within a casing? Can an operator use GWUT as a means of conducting a direct examination of a pipeline within a casing?[09/08/2011]

FAQ-278.If an operator determines that a short exists at a cased crossing, clears the short, must a direct examination of the cased pipeline be performed? What would constitute an acceptable direct examination?[09/08/2011]

FAQ-269.What are the definitions of DA, Direct Assessment and DE, Direct Examination?[06/16/2010]

FAQ-270.If no casings with a region (hazardous liquids) test as electrically shorted to the carrier pipe but there is one DCVG indication near one of the casing ends - what direct exams are required? Of course, the end of the casing that might contain the DCVG indication should be one direct exam and the other end of that same casing should be another direct exam. But, for the rest of the casings that have no indications nearby, does examining both ends of one casing constitute one direct exam or is excavation of each end of a casing considered as two direct exams?[06/16/2010]

FAQ-271.How will PHMSA handle casing assessments made before the guidance material was made public (when operators used ECDA but may not have followed the guidelines entirely)?[06/16/2010]

FAQ-272.How would one handle a cased segment that has the attributes of Item 1 and Item 4 (from Exhibit B)? For example, a casing that has an attribute of Item 1, no attributes of Items 2-6, and perhaps some attributes from Items 7-17, could be placed in, say, Region A. Another casing that has an attribute of Item 4, no attributes of Items 2-6, and perhaps some attributes from Items 7-17, would be required per the guidance to be placed into a different region, say, Region B. How then would one regionalize a cased segment that has the attributes of Items 1 and 4, no attributes of Items 2, 3, 5, or 6, and then perhaps some attributes from Items 7-17? Should this segment be considered as Region A, Region B, or a whole new region, say, Region C? If each different combination of Items 1-6 required a new region to be established, this could then entail a million different regions before one even begins considering the "C" attributes from Items 7-17.[06/16/2010]

FAQ-273.If an operator has a pipeline system that operates at pressures less than 30% SMYS, and conducts a baseline assessment for external corrosion on all cased pipe using ECDA, can subsequent re-assessments be conducted using the low stress reassessment method (49 CFR 192.941), even though all of the casings were not directly examined during the baseline assessment?[06/16/2010]

FAQ-274.Must an operator always perform a 100% direct examination inspection of the carrier pipe within the casing under Step 3, Direct Examination, when doing an ECDA assessment?[06/16/2010]

FAQ-254.Each Casing in Their Own Region: Is it permissible for an operator to place each of its cased crossings in separate region regardless of similarities with other cased crossings?[04/20/2010]

FAQ-248.What are the basic regulatory requirements for cased pipe monitoring and inspection and what code sections apply?[03/01/2010]

FAQ-249.Incorrect Pre-Assessment Data: If an operator creates regions based on pre-assessment data and during the direct examination determines that construction documentation was incorrect and the cased pipe should have been in a different region, does the operator have to perform additional direct examinations on cased pipe in that region? For example, an uncoated carrier pipe was documented as being coated, or an unfilled casing was documented filled.[03/01/2010]

FAQ-250.No Previous Monitoring Data: If an operator has cased pipe that has not been monitored on an annual basis (no annual C/S readings) because casing wires and vents were not installed, but the operator has documentation on the construction, including the original pressure test, of the cased pipe and the indirect inspection results show that the casing is not shorted to the carrier pipe, what must the operator do to assess and monitor the pipeline during future assessments.[03/01/2010]

FAQ-251.Filled, Shorted, and an Incomplete Inspection: If an operator performs Guided Wave Ultrasonic Testing (GWUT) on a shorted and filled cased pipe, but is unable to clear the short and does not get 100% coverage with the GWUT inspection, has the operator satisfied the assessment requirements?[03/01/2010]

FAQ-252.Filled, Isolated, and Not Following Go-No Go Target Items: If an operator does not have a prior assessment on a filled, cased pipe and completes a GWUT inspection, but is unable to follow all of the GWUT Go-No Go Target Items, has the operator satisfied the assessment requirements? For example, the operator does not remove the end seals because they do not want to lose the filler material.[03/01/2010]

FAQ-253.Fifty Casings in One Region: If an operator places all of their cased crossings in one region regard-less of specific differences in casings based on the pre-assessment data, is this always wrong?[03/01/2010]

FAQ-255.Reassessment on Filled Casings that have not Experienced a Major Change in Status: The guidelines state that "[a]ny indication of a change in casing integrity, or (for a filled casing) fill level or fill quality based on an evaluation of the casing monitoring program data using the guidelines in Exhibit D" is an indication with "immediate" priority. Would minor changes that are expected or for which there is a valid explanation meet this criteria for an "immediate" priority? For example, the fill level may have dropped a few inches because it was a hot summer and the vents warmed up. They would need to: 1) verify that no shorts exist, 2) if significant fill loss they would need to investigate why, and 3) repair and refill. If no shorts exist I do not see the need to reassess.[03/01/2010]

FAQ-256.All Casing Low Risk: Do small operators with very few cased crossings still have to do a direct examination even if all of their cased crossings are low risk and filled?[03/01/2010]

FAQ-257.Direct Examinations to Demonstrate ECDA Effectiveness: Do small operators with very few cased crossings still have to do effectiveness digs on cased crossings? The concept of combining regions is good, but at some point all operators, small and large, will not see any risk benefit in effectiveness examinations.[03/01/2010]

FAQ-258.Corrosion Growth Rate: What is the proper method for determining corrosion growth rate that should be used on cased crossings when calculating reassessment intervals?[03/01/2010]

FAQ-259.Protection of Casing: Do I have to cathodically protect a casing?[03/01/2010]

FAQ-260.Monitoring Casing Integrity: How are operators expected to monitor structural integrity of the casing and end seals?[03/01/2010]

FAQ-262.Minimum Number of Direct Examinations: An operator has multiple casing regions in a pipeline segment and each region has multiple casings. A variety of immediate, scheduled, and monitored indications were identified. How many direct examinations must be made in the ECDA process?[03/01/2010]

FAQ-263.Direct Examination Example #1: An operator has two casing regions in a pipeline segment which are being assessed by ECDA. Region A has multiple casings, some of which are filled and some of which are unfilled. Region B has multiple casings, all of which are filled. There are no "immediate" or "scheduled" indications at any of the casings. All indications in both regions are "monitored." How many direct examinations need to be performed?[03/01/2010]

FAQ-264.Direct Examination Example #2: An operator has a pipeline segment with one region containing 5 filled casings. During indirect examination performed for a 7-year reassessment, the operator identifies that one of the casings is metallically shorted to the carrier pipe. None of the other four casings had any indications. How many direct examinations need to be performed?[03/01/2010]

FAQ-265.Direct Examination Example #3: An operator has a pipeline segment with one Region containing 3 filled and 2 unfilled casings. During indirect examination performed for an initial assessment, the operator identifies that one of the filled casings is metallically shorted to the carrier pipe and that both unfilled casings have electrolytic shorts. None of the other casings had any indications. How many direct examinations need to be performed?[03/01/2010]

FAQ-266.Direct Examination Example #4: An operator has a pipeline segment with two regions: Region A has 5 casings (3 unfilled and 2 filled) and Region B has 5 unfilled casings. During indirect examination performed for a 7-year reassessment, the operator identifies that one of the unfilled casings in Region A is electrolytically shorted to the carrier pipe. None of the other casings in either region had any indications. How many direct examinations need to be performed?[03/01/2010]

FAQ-267.If a casing has been filled with wax per the PHMSA guidelines and a monitoring program has been implemented and followed in accordance with the PHMSA guidelines, does the casing have to be reassessed every 7 years if testing indicates there are no immediate indications?[03/01/2010]

FAQ-268.Once an operator has wax filled a casing, does this allow the operator to reprioritize the filled casing within the next integrity re-assessment cycle?[03/01/2010]